This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Hydraulic fracturing (sometimes referred to herein as “hydrofracturing,” hydrofracking,” or “fracking”) is a technique in which a mixture of a liquid (e.g., water with a chemical additive that provides appropriate viscoelastic properties) mixed with proppants (generally, small grains of sand or aluminum oxide with diameters between 0.1 millimeters (“mm”) to 0.3 mm) is injected through a well borehole at high pressure into a geological formation (e.g., an oil/gas reservoir). This creates fractures in the deep rock formation, typically less than 5 mm wide, 10 meters (“m”)-100 m long, and 10 m-100 m high, along which oil and/or gas, as well as water, migrate to a producing well. When the hydraulic pressure is removed from the formation, then the small grains in the proppant hold these fractures open. Both the locations of fractures that are created and the dimensions of the created openings, which are important for determining the hydraulic conductivity of the fractures and the efficacy of the fracture, are difficult to determine. Thus, mapping of the fractures that remain open upon the removal of the fracking pressure is important since neither the location, orientation, size of the openings, nor the drainage area of the fracture is well known.
However, mapping fractures in geological formations is a difficult problem because of the extreme spatial anisotropy of a fracture, which may feature a width of barely a millimeter and extend in height and length over an area covering approximately 30 m by 100 m. Creating a fracture often appears as a random process, since the underlying over burden pressure, rock type, and anisotropy are not known. Neither the shape nor extent of the created fracture can be predicted. Therefore, the amount of oil and/or gas that it may produce is uncertain as well. Imaging the fractures is of critical importance to the industry, and currently no methods exist that provide satisfactory detailed information about the geometrical and spatial features of the fractures.
The current fracturing practice is a highly developed technology with a strongly ingrained infrastructure and is an expensive operation often involving millions of gallons of fluids and a very large amount of proppants (e.g., approximately 300,000 pounds (136 metric tons)) per job. Typically, 90% of the injected proppant mixture is water, 9.5% is proppant (e.g., sand or ceramic particles), and about 0.5% may include a chemical additive. The pumps and accessories are designed to pump the proppant mixture in massive amounts. If the oil and gas industry is to accept contrast agents or alternative proppant additive materials, then these will need to be producible at low cost (at least substantially equivalent to current sand or ceramic proppant costs).
In addition, such proppant additives should adhere to the following:
1. The proppant additive should have similar flow and dispersion properties as conventional proppants with which they are injected into the fracture system. Therefore, the density of the proppant additive should be similar to that of conventional proppants.
2. The proppant additive should be sufficiently strong to withstand the dynamic pressure that is exerted when the fracture tries to close after the pump pressure is relieved.
3. The proppant additive should have a high contrast—either dielectric or conductive or both.
Currently, limited techniques exist for detecting fractures. A passive technique sometimes used to geo-locate the fractures, referred to as “Microseismic,” relies on the bursting sound (acoustic noise) the fractures produce when opening under the hydraulic pressure. However, this technique is not reliable, since some fractures are likely to close immediately upon the removal of the external pressure. And, this technique provides no information on the sizes and shapes of the opened fractures that provide the pathways for the drained oil and/or gas. Microseismic also fails to distinguish between the fractures that will remain open after the removal of pressure and those that close. Since many of the initial fractures close and are of no importance to the reservoir drainage area, Microseismic results in images that likely contain numerous irrelevant fracture predictions. In addition, the Microseismic imaging is imprecise in terms of determining the exact locations of the induced fractures, and yields a low resolution image for the fractured rock volume.
Other techniques have used tracers included with the injected fluids, but these techniques do not provide completely reliable data, as the tracers can leak into the formation and do not necessarily remain in the fractures.
Aspects of the present disclosure map fractures with small (e.g., micron to millimeter sized) proppant additives, which are mechanically compatible with oxides and sand particles that are generally used in hydraulic fracturing, by imaging the fractures that remain open after the pump pressure is removed using the proppant additives. The art of hydrofracking is well developed, and pumping involves massive and expensive machines. Therefore, it is important that the disclosed additives can be deployed using the current hydraulic fracturing infrastructure.
Disclosed herein are implementations and specific materials pertaining to the present invention, but aspects of the present disclosure are not limited to these specific ones. Herein, mapping refers to the utilization of some type of contrast agent that has been injected into a geological formation, thus penetrating into the pores and cracks (including hydraulically-induced fractures) of the formation, and then using some sort of imagine techniques (e.g., electromagnetic (“EM”) imaging) to determine the locations of the contrast agent within the formation due to its EM-related measurement properties being measurably different than the EM-related measurement properties of the surrounding media (e.g., materials composing the geological formation). In this context, “measurably different” means that there is a way (e.g., by using appropriate equipment) to distinguish between a measurement made of an EM-related measurement property (e.g., complex conductivity) of a contrast agent (e.g., proppant additive particles) located within a media (e.g., a geological formation) and a measurement made of the EM-related measurement property of the surrounding media.
Proppant additives disclosed herein may be configured with special EM-related measurement properties (e.g., complex conductivity), which are sufficiently different (i.e., functions as a contrast agent) from the background (e.g., materials composing the geological formation) so that they become “visible” by EM measurement techniques so that features of the geological formation (e.g., fractures formed by the fracking) can be imaged and mapped. As a result, proppant mixtures disclosed herein are configured so that they result in a significantly increased complex conductivity contrast between the proppant-filled fractures and the surrounding geological formation, and thus an EM technique can detect and map the fractures.
Aspects of the present disclosure measure the complex conductivity, i.e., both the real and the imaginary part. The imaginary part of the conductivity may be referred to herein as “IP” or dielectric, and the real part referred to as conductivity. Generally, it is difficult to obtain a large contrast in conductivity (real part) using granular proppants, as these particles need to physically touch each other in order to provide a “percolating” conductive path (also referred to herein as the “electrical percolation threshold”). That generally requires about 60% of the additive to be conductive. There is no such limitation for the dielectric contribution.
Aspects of the present disclosure may include nanomaterials along with the proppants, which can leak into the unpropped formation (i.e., portions of the geological formation other than the created fractures) and provide further information about the fractured region.
Aspects of the present disclosure utilize induced polarization (“IP”) or dielectric enhancement in proppant additives of functionalized silica and/or coke breeze, which are mechanically compatible with currently deployed proppants, such as sand. Being an additive, the volume percentage (v %; also referred to herein as “volume concentration” or “concentration”) may be below the aforementioned electrical percolation threshold, and thus will not provide a conductivity (real part of the complex conductivity) contrast. However, aspects of the present disclosure provide an extraordinarily large dielectric contrast, even with a low volume percentage (e.g., <60%) in the proppant fluid. If a large volume concentration fraction is utilized (with the concomitant large conductivity of these contrast materials), it can be used as a conductivity contrast.
Use of the real part of conductivity contrast has been known, and some proposals with specific set-ups (i.e., tool configurations) and specific materials have been proposed. The conductivity (i.e., real part alone) measurements proposed here have some elements in common with, but is not limited to, what has been proposed. Conductivity techniques have previously been proposed to measure the conductivity of a fracture by EM methods (see, Pardo et al., “Sensitivity analysis for the appraisal of hydrofractures in horizontal wells with borehole resistivity measurements,” Geophysics, 78, pp. D209-D222, 2013). They are limited to one specific contrast agent and one specific measurement set-up (induction) that is limited to a single well borehole. Aspects of the present disclosure are neither limited by material to be used, nor by the specific induction method in a single well borehole. Aspects of the present disclosure provide a novel sensitivity analysis of through-casing (wellbore) resistivity measurements. For an open hole, Pardo et al. used both magnetic dipole and electric dipoles they claim impress a ring of magnetic current and “electrodes that generate only an Hϕ component of the magnetic field, i.e., Hρ=Hz=0 is the transverse magnetic (TM) mode.” However, Pardo et al. do not consider IP effects.
In contrast, aspects of the present disclosure are not restricted to any particular modality, electrode, or coil configuration.
Aspects of the present disclosure utilize crosswell as well as well-to-surface methods using, among other techniques, galvanic methods. Such methods fail in the prior art because at such a high volume of contrast agent, the cost is prohibitive. Pardo et al.'s method fails because it does not measure the complex conductivity or IP/dielectric properties. When particles do not touch (exceeding the electrical percolation threshold), conductivity contrast alone is not enough for mapping using such a technique.
Techniques disclosed by Hoverstein et al. (see Poster WS9-008, 76th EAGE Conference & Exhibition, 2014, “Hydro-frac Monitoring Using Ground Time-domain EMG,” M. Hoverstein (Chevron), M. Commer (Lawrence Berkeley National Laboratory), E. Haber (University of British Columbia) and C. Schwarzbach (University of British Columbia)) are limited to the real part of conductivity contrast alone, and study transient decay responses from fracture zones with steel casing as a source. Their materials and the specific borehole methods are also limited.
International Patent Application No. PCT/US2013/043603 disclosed a water-flood mapping technique using nanoparticles. However, nanoparticles are generally too small to keep fractures open, and they may leak into the formation.
Barber et al., in U.S. Published Patent Application No. 2011/0309835A1, proposed to inject conductive fluid and use an IP or a complex conductivity method. However, this technique failed because it did not consider insulating surface active proppants or matching the density of proppant material to that of sand. To be more specific, Barber et al. is limited to specific types of materials (i.e., conducting particles) that produce the IP effects by a specific electrochemical method (oxidation-reduction or Faradaic processes at the interfaces). To provide Faradaic conduction, Barber et al. specifically use the data of Klein and the theory of Wong (see references cited in paragraph [0026] in US 2011/0309835A1; Klein et al., “Mineral interfacial processes in the method of induced polarization,” Geophysics, July 1984, Vol. 49, No. 7, pp. 1105-1114; and J. Wong, “An electrochemical model of the induced-polarization phenomenon in disseminated sulfide ores,” Geophysics, July 1979, Vol. 44, No. 7, pp. 1245-1265) that limits it to surface processes of a specific type. In general, however, ions such as Na+ and Cl− are not able to penetrate the lattice structure of the metal, and the metal is not a source for these ions, so the method of Barber et al. is limited to special metals and special environments where a redox reaction can take place, i.e., when the electrolyte contains active ions that can engage in electrochemical charge transfer reactions. The materials (like pyrite) proposed by Barber et al. have high density, and therefore, are not suitable for pumping using the current hydraulic fracturing infrastructure.
Electro-static self or streaming potential techniques, such as proposed in U.S. Published Patent Application No. 2012/0169343, suffer from the drawback of being subjected to the electrode potentials. The electrodes themselves develop static potential that can vary with salinity and pH without the influence of a contrast agent.
Aspects of the present disclosure may employ metallic and/or nonmetallic additives that produce various surface activities (i.e., not limited to oxidation-reduction) for implementing an enhanced dielectric constant. Among other things, aspects of the present disclosure may use clay-like non-conducting materials that derive enhanced dielectric from counter-ions via a completely different mechanism than is involved for metals. Aspects of the present disclosure may use carbonaceous materials, like coke breeze, which are neither metallic nor clay-like, i.e., have little or no zeta potential yet show high dielectric constant. Aspects of the present disclosure may use materials that involve a combination of Faradaic (oxidation-reduction) and non-Faradaic (ideally or partially polarizable) counter-ions and functional groups.
Aspects of the present disclosure may employ induction and/or galvanic methods, using coil electrodes and casing. The geometrical configuration of aspects of the present disclosure is not limited to single borehole configurations as in the above prior art. Aspects of the present disclosure may employ single borehole, cross-hole, surface-to-borehole and borehole-to-surface modalities. For the galvanic methods using IP mode, the proppant additive may have a large dielectric signature at low to medium frequencies (e.g., around 100 Hz).